The present application relates to exploration and development of subterranean hydrocarbon-bearing formations. More specifically, the present application relates to evaluation of kerogen rich unconventional hydrocarbon-bearing shale reservoirs.
Shale is an abundant sedimentary rock of extremely low permeability. It is often considered a natural barrier to the migration of oil and gas. In organic rich shales, the oil and gas is generated in place. The organic shale acts as both the source rock and the reservoir. The hydrocarbons can be stored interstitially within the pore spaces between rock grains or fractures in the shale, or it can be adsorbed to the surface of organic components contained within the shale. This is in contrast to conventional gas reservoirs in which gas migrates from its source rock into a sandstone or carbonate formation where it accumulates in a structural or stratigraphic trap, often underlain by a gas/water contact. Therefore, organic rich shales are considered unconventional reservoirs.
Shale-hydrocarbon is produced from continuous accumulations, which may have the following characteristics: regional extent, lack of an observable seal and trap, absence of a well-defined gas/water contact, natural fracturing, estimated ultimate recovery that is generally lower than that of a conventional accumulation, and very low matrix permeability. Furthermore, economic production depends heavily on completion technology.
Despite their apparent shortcomings, in the USA and other parts of the world, certain shales are being targeted for production—those with the right combination of shale type, organic content, maturity, permeability, porosity, hydrocarbon saturation and formation fracturing. When these formation conditions are triggered by favorable economic conditions, the unconventional shale-hydrocarbon play becomes a boom. Today's shale-hydrocarbon plays are taking off, due in large part to a growing demand for gas and to a growing range of advanced oilfield technologies.
Shale comprises clay- and silt-sized particles that have been consolidated into rock layers of low permeability. Clearly, this description offers little to commend shale as a target for exploration and development. However, some shales are known to contain enough organic matter to generate hydrocarbons. Whether these shales are actually capable of generating hydrocarbons, and whether they generate oil or gas, depends largely on the amount and type of organic material they contain; the presence of trace elements that might enhance chemogenesis; and the magnitude and duration of heating, pressure, and diagenesis to which they have been subjected.
Organic matter (the remains of animals and/or plants) can be thermally altered to produce oil or gas. Before this transformation can take place, however, these remains are first preserved to some degree. The degree of preservation will have an effect on the type of hydrocarbons the organic matter will eventually produce. Most animal or plant material is consumed by other animals, bacteria or decay, so preservation involves quick burial in an anoxic environment that will inhibit most biological or chemical scavengers. This requirement is met in lake or ocean settings that have restricted water circulation, where biological demand for oxygen exceeds supply. Even in these settings, however, anaerobic microorganisms can feed off the buried organic matter, producing biogenic methane in the process. Further sedimentation increases the depth of burial over time. The organic matter slowly cooks as pressure and temperature increase in concert with greater burial depths. With such heating, the organic matter is transformed into kerogen. Depending on the type of kerogen produced, further increases in temperature, pressure and time may yield oil, wet gas or dry gas. Kerogen has been classified into four broad groups (Types I, II, III and IV), each of which has a distinct bearing on what type of hydrocarbons, if any, will be produced.
Type I kerogen is generated predominantly from lacustrine environments and, in some cases, marine environments. It is derived from algae, planktonic or other organic matter that has been strongly reworked by bacteria and microorganisms living in the sediment. Rich in hydrogen and low in oxygen, it is prone to oil production, but can also produce gas, depending on its stage of maturation. Type I kerogen is not found widely, and it is estimated that Type I kerogen is responsible for 2.7% of the world's oil and gas reserves.
Type II kerogen is generated in reducing environments found in moderately deep marine settings. Type II kerogen is derived primarily from the remains of plankton that have been reworked by bacteria. It is rich in hydrogen and low in carbon. It can generate oil or gas with progressive heating and maturation. Sulfur is associated with this type of kerogen, either as pyrite and free sulfur, or in organic structures of the kerogen.
Type III kerogen is derived primarily from terrestrial plant debris that has been deposited in shallow to deep marine or non-marine environments. Type III kerogen has lower hydrogen and higher oxygen content than Types I or II, and consequently generates mostly dry gas.
Type IV kerogen is derived from older sediments redeposited after erosion. Prior to deposition, it may have been altered by sub-aerial weathering, combustion or biological oxidation in swamps or soils. This type of kerogen includes residual organic matter with high carbon content and very little hydrogen. It is considered a form of “dead carbon,” with very limited potential for generating hydrocarbons.
From this discussion, it can be generalized that marine or lacustrine kerogen (Types I and II) tends to produce oils, while kerogen of terrestrial origin (Type III) produce gas. Intermediate blends of kerogen, especially blends of Types II and III, are most common to marine shale facies. A theme prevailing within the kerogen classification scheme pertains to hydrogen content. Hydrogen-rich kerogen (Types I and II) plays a greater role in generating oil. Conversely, kerogen with lower amounts of hydrogen (Type III) plays a greater role in generating gas. After hydrogen is depleted from the kerogen, generation of hydrocarbons will cease naturally, regardless of the amount of available carbon.
Geological processes for converting organic material to hydrocarbons involves heat and time. Heat gradually increases over time as the organic matter continues to be buried deeper under increasing sediment load. Time is measured over millions of years. Through increasing temperature and pressure during burial, and possibly accelerated by the presence of catalyzing minerals, organic materials give off oil and gas. This process is complicated and not fully understood; however, the conceptual model is fairly straightforward. Microbial activity converts some of the organic material into biogenic methane gas. With burial and heating, the remaining organic materials are transformed into kerogen. Further burial and heat transform the kerogen to yield bitumen, then liquid hydrocarbons, and finally thermogenic gas-starting with wet gas and ending at dry gas. The process of burial, conversion of organic matter and generation of hydrocarbons can generally be summed up in a sequence of three steps (diagenesis/catagenesis/matagenesis).
Diagenesis is often characterized by low-temperature alteration of organic matter, such as at temperatures below about 50° C. [122° F.]. During this stage, oxidation and other chemical processes begin to break down the organic material. Biological processes will also alter the amount and composition of organic material before it is preserved. At this point, bacterial decay may produce biogenic methane. With increasing temperatures and changes in pH, the organic matter is gradually converted to kerogen and lesser amounts of bitumen. During the early phases of diagenesis, sulfur may be incorporated into the organic matter. Sulfates in seawater provide the oxidant source for biodegradation of organic matter by sulfate-reducing bacterial colonies. These bacteria release polysulfides, hydrogen sulfide [H2S] and native sulfur, which can later recombine with iron in clays to form pyrite [FeS2], or combine with the organic matter to form other organosulfur compounds.
Catagenesis generally occurs as further burial causes more pressure, thereby increasing heat in the range of approximately 50° C. to 150° C. [122° F. to 302° F.], causing chemical bonds to break down within the shale and the kerogen. Hydrocarbons are generated during this process, with oil produced by Type I kerogen, waxy oil produced by Type II kerogen, and gas produced by Type III kerogen. Further increases in temperature and pressure cause secondary cracking of the oil molecules, resulting in production of additional gas molecules.
Metagenesis is the last stage, in which additional heat and chemical changes result in almost total transformation of kerogen into carbon. During this stage, late methane, or dry gas is evolved, along with non-hydrocarbon gases such as CO2, N2 and H2S. In basins where these changes take place, temperatures generally range from about 150° C. to 200° C. [302° F. to 392° F.]. This process of kerogen alteration, commonly known as “maturation,” produces a series of progressively smaller hydrocarbon molecules of increasing volatility and hydrogen content, eventually arriving at methane gas. And as the kerogen evolves through thermal maturity, its chemical composition progressively changes, transforming into a carbonaceous residue of decreasing hydrogen content, eventually ending as graphite.
The preservation and maturation of organic matter are not unique to gas shales. The model for generating oil and gas is actually the same for conventional and unconventional resources. The difference, however, is location. In conventional reservoirs, oil and gas migrate from the source rock to the sandstone or carbonate trap. In unconventional shale-gas reservoirs, hydrocarbons are produced directly from the source rock.
Source-rock potential is primarily determined through geochemical analysis of shale samples, often in conjunction with detailed evaluation of logs from previously drilled wells. Geochemical testing is carried out on whole cores, sidewall cores, formation cuttings and outcrop samples. The primary aim of testing is to determine whether the samples are organic-rich and whether they are capable of generating hydrocarbons. In general, the higher the concentration of organic matter in a rock, the better its source potential.
A variety of sophisticated geochemical techniques have been developed to assess the total organic carbon (TOC) and maturity of samples. TOC values can be obtained from 1-gram samples of pulverized rock that are treated to remove contaminants, then combusted at 1,200° C. [2,192° F.]. Carbon contained in the kerogen is converted to CO2 or CO. The evolved carbon fractious are measured in an infrared cell, and converted to TOC, recorded as mass weight percent of rock. If this initial screening test detects samples of sufficient organic richness, they will be subjected to additional testing.
To further characterize organic richness, many geochemical laboratories use a programmed pyrolysis technique developed by the Institut Français du Parole. This method, which has become an industry standard for geochemical testing of source rock, involves approximately 50 mg to 100 mg of pulverized rock, and can be carried out in about 20 minutes. Each sample is heated in controlled stages through a pyrolysis test. During the first stage of heating to 300° C. [572° F.], free hydrocarbons in the rock are released from the matrix. As heat increases during the second stage to 550° C. [1,022° F.], volatile hydrocarbons formed by thermal cracking are released. In addition to hydrocarbons, the kerogen gives off CO2 as temperatures climb from 300° C. to 390° C. [572° F. to 734° F.]. Organic compounds released through heating are measured by a flame-ionization detector. These measurements, along with temperature, are recorded on a chart and show three distinct peaks. These peaks give geochemists insight into the relative abundance of hydrogen, carbon and oxygen in the kerogen. With this information, geochemists can determine kerogen type and potential for oil and gas generation. The temperature at which the maximum release of hydrocarbons is detected corresponds to the tip of the S2 peak, and is called Tmax. The thermal maturation of a sample can be tied to the value of Tmax.
Vitrinite reflectance is another diagnostic tool for assessing maturation. A major component of kerogen, vitrinite is a shiny substance formed through thermal alteration of lignin and cellulose in plant cell walls. With increasing temperature, vitrinite undergoes complex, irreversible aromatization reactions, resulting in increased reflectance. Vitrinite reflectance was first used to diagnose the rank, or thermal maturity, of coals. This technique was later carried over to evaluate thermal maturity of kerogen. Because reflectance increases with temperature, it can be correlated to temperature ranges for hydrocarbon generation. These ranges can be further divided into oil or gas windows. Reflectivity (R) is measured through a microscope equipped with an oil-immersion objective lens and photometer. Vitrinite-reflectance measurements are carefully calibrated against glass- or mineral-reflectance standards, and reflectance measurements represent the percentage of light reflected in oil (Ro). When a mean value of vitrinite reflectivity is determined from multiple samples, it is designated as Rm. As an indicator of thermal maturity, Ro values vary from one organic type to another. This means that the onset of hydrocarbon generation in Type I kerogen may be different than in Type II kerogen. And because the temperature range of the gas window extends beyond that of oil, Ro values for gas will show a corresponding increase over those of oil. Thus, high maturation values (Ro>1.5%) generally indicate the presence of predominantly dry gas; intermediate maturation values (1.1%<Ro<1.5%) indicate gas with an increasing tendency toward oil generation at the lower end of the range. Wet gas can be found still lower in the range (0.8%<Ro<1.1%). Lower values (0.6%<Ro<0.8%) indicate predominantly oil, while Ro<0.6% points to immature kerogen. By themselves, Ro values can sometimes be misleading, and should be weighed along with other measurements. Other common indicators of maturity involve the thermal alteration index (TAI), based on microscopic examination of spore color; pyrolysis temperature evaluation; and, to a lesser extent, conodont alteration index (CAI), based on examination of tiny fossilized teeth. Owing to the popularity of vitrinite reflectance, these other indicators are often correlated to Ro values.
Other shale properties can be estimated from well logs, which in some cases produce distinctive signatures. High gamma ray activity is thought to be a function of kerogen in the shale. Kerogen generally creates a reductive environment that drives the precipitation of uranium, which influences the gamma ray curve. Resistivity may be high because of high gas saturations, but varies with fluid content and clay type. Bulk densities are often low because of clay content and the presence of kerogen, which has a low specific gravity of 0.95 to 1.05 g/cm. Well logs are also used to ascertain the complex mineralogy of shale and to quantify the amount of free gas in the pores of the source rock. Petrophysicists have used a combination of conventional triple-combo and geochemical logs to determine the organic carbon content of the shale and calculate for adsorbed gas. Geochemical logs also enable petrophysicists to differentiate types of clays and their respective volumes, information useful for calculating producibility and for determining which fluid to use during subsequent hydraulic fracturing treatments.